Wood Mackenzie has released its Global gas and LNG – 6 things to watch for in 2022 report.
Prices to fall if Nord Stream 2 is commissioned. But get ready for another bumpy year ahead.
As global LNG prices continue to trade at record highs, there are two key elements that will define prices in 2022: winter weather dynamics and the timing of Nord Stream 2 start-up. Wood Mackenzie’s analysis suggests that at current levels of Russian exports and considering normal weather conditions, European storage inventories will get below 15 billion cubic metres (bcm) by the end of March, a record low. Prices will eventually come down as the winter is through, but requirements to refill storage facilities will be high, some 20-25 bcm more than last year. The commissioning of Nord Stream 2 might well be the only option to refill storage and avoid a repeat of last year’s winter crisis.
Vice president Massimo Di Odoardo said: “Weather dynamics in Asia will dictate whether the recent wave of US LNG imports to Europe will continue beyond January, limiting storage withdrawals and helping rebalancing the market.”
“But Europe is not out of the woods yet. Cold weather in Asia could see local utilities for deliveries in February and March, limiting LNG availability to Europe. A cold winter in Europe could add up to 10 bcm of additional gas demand, pushing storage inventories close to zero before the end of March. And the commissioning of Nord Stream 2 could be stopped altogether if tensions between Russia and Ukraine escalate, as the German government has recently warned.
“Normal winter weather, including in Asia, and visibility on Nord Stream 2 commissioning would push prices down, although demand for storage (and high carbon prices) will maintain prices above US$15 per metric million British thermal units (mmbtu). But a cold winter in Europe and Asia, alongside continued uncertainty about commissioning of Nord Stream 2, could see prices increase further throughout 2022 – get ready for another bumpy year ahead.”
Oil-indexation levels to rise, potentially reaching 12% on a weighted average basis. Contracts starting before 2025 attracting premiums while those starting after priced at a discount.
Oil indexation in long-term LNG contracts has been on a declining trend for the past 10 years, a consequence of increased availability of uncontracted supply, more recently from Qatar, and reduced appetite for long-term contracts in favour of more spot exposure.
But 2022 will be a turning point for LNG oil-indexed contracts, with the level of indexation firmly on the rise. With Asian LNG spot prices expected to average close to US$15/mmbtu over the next five years, the current level of oil indexation (and oil prices) will result in a US$7/mmbtu annual average discount over spot LNG. Inevitably, demand for long-term contracts will increase, pushing oil indexation levels up.
Contracting requirements remain different across the next 10 years. Through to 2025, limited uncontracted supply availability is fuelling concerns regarding security of supply, pushing oil-indexed
levels up. Beyond 2025, price upside will be kept in check by increased availability of uncontracted supply from Qatar and Russia, uncertainties about long-term demand from legacy northeast Asia buyers, and competitive Henry Hub plus contracts.
Oil-indexation levels will rise, potentially reaching 12% on a weighted average basis. But the market will remain bifurcated, with contracts starting before 2025 attracting premiums while those starting after priced at a discount.
Vice president Valery Chow said: “2021 saw the return of contracting activity to its highest levels over the last five years. Asia accounted for 85% of global contracts signed, with China leading the pack.
“We expect LNG contracting activity to remain strong in 2022. Chinese buyers are again expected to lead the way and account for most of new long-term contracts signed. On the other hand, we expect more muted activity from Japanese buyers. Despite high spot prices, long-term contracting for Japan is anticipated to continue softening in the face of energy transition uncertainties and greater confidence in the trading capabilities of the major buyers.
“Hybrid and Henry Hub-linked contracts are expected to remain in vogue in 2022 due to the price benefits of Henry Hub contracts and availability of new US supply. In contrast, we expect few long-term JKM-linked deals as buyers remain fearful of the associated price volatility.”
There is momentum behind new LNG projects, but FIDs are unlikely to come from Majors’ sponsored projects in 2022.
With LNG prices expected to be structurally higher and oil indexation on the rise, there is plenty of momentum behind new LNG projects. Wood Mackenzie expects 79 million tonnes per annum (mmtpa) of additional LNG to take final investment decision (FID) over the next two years, including 33 mmtpa in North America, 16 mmtpa in Qatar and 20 mmtpa in Russia. And there is potential for upside.
Oil Majors have been on the sidelines so far, but some action is likely in 2022. We expect several of them to conclude negotiations with QatarEnergy to secure a slice of the North Field East development. TotalEnergies might well acquire a share of Novatek’s Arctic LNG-1 project, similar to what it did at Arctic-2 and Yamal. And it is also possible that Majors will continue to secure offtake deals with third-party projects in North America, on both the Eastern and Western seaboards. However, a Major sponsoring one of its equity projects in 2022 seems unlikely.
Gas will continue to be a pillar of Majors’ energy transition strategies, but their optionality for investments in brownfield and greenfield equity projects remains limited for now.
Priority shifts from offsetting CO2 emissions to material carbon reduction but still no FID on more capital-intensive measures (such as CCS).
Carbon-offset LNG flourished in 2021, with 28 cargoes announced, a five-fold increase compared to 2020. However, the enthusiasm appears to be fading, possibly because of high LNG prices but also a consequence of increased criticism to what had started to be seen as a ‘greenwashing’ practice because of the low quality and costs of the offsets.
This will push the LNG industry to focus on CO2 reduction across the value chain, which must be the ultimate goal, with offsets deployed only for unavoidable emissions.
Some companies have already been moving in that direction, but the focus has so far been on the low-hanging fruit. Producers have been exploring programmes to reduce flaring, venting and methane leakages, while LNG developers in the US have been looking at procuring gas certified by third parties that is closer to the plant and with low methane emissions (responsibly sourced gas, or RSG). However, more capital-intensive projects, including use of low-carbon power and/or carbon capture and storage (CCS), remain at an evaluation stage.
The US will be the place to watch, also because of a tax credit of up to US$50/t for CCS developments. But a suitable global carbon price associated with energy trade might be required for substantial investments to be spent in reducing Scope 1 and 2 emissions – and that is still a few years off.
Global gas demand will remain resilient in the short term, but the role of gas in the energy transition will come under pressure as prices remain high.
Signs of demand destruction have been limited so far. Despite strong economic growth in Europe, gas demand in industry and power is down 4% since the summer, compared to the past five years. In Asia, LNG demand has continued to increase as most supply is priced at legacy oil-indexed contracts, currently trading at half the value of Asian LNG spot prices.
Di Odoardo said: “Eventually, though, higher prices will put pressure on demand. In Asia, the rationale to switch from coal to gas will diminish, as higher spot LNG prices will translate into higher oil-indexed contract prices.
“Meanwhile, investment in renewables and batteries will increase, limiting the headroom for gas demand to grow. And in Europe, where the move towards renewables is already underway, policy makers will look to accelerate the shift away from natural gas, as the recent EU proposal to support biomethane and hydrogen suggests.”
Gas to be considered as transitional investment in the EU taxonomy, but this is no panacea for the gas industry.
EU Member States will be debating the taxonomy for sustainable investments after the European Commission released its latest version, classifying efficient unabated gas-fired power plants as transitional investments.
On the face of it, whether unabated gas-fired plants will be defined as “transitional investments” in the EU taxonomy could be a moment of truth for the global gas industry. Financial and non-financial investors will be able to increase their corporate “green scoring” by investing in gas, including outside Europe. Other countries developing similar taxonomies will be emboldened to include gas too, particularly in Asian markets where coal still dominates, as South Korea has recently proposed.
Di Odoardo said: “But the EU recognition of gas power plants as a transitional investment is no panacea for the gas industry. Gas prices will need to come down to accommodate increased investments in gas use. And the proposed CO2 emission cap of 270g/KWh, alongside the commitment to use at least 30% of renewable or low carbon gas by 2026 and 100% by 2035, means that the use of conventional natural gas would need to reduce over time if a gas fired power plant has to be classified as “transitional”. The use of unabated natural gas in the EU is set to decline, even if the EU classifies investments in gas-fired plants as transitional investments.”